U.S. patent number 6,668,554 [Application Number 09/393,397] was granted by the patent office on 2003-12-30 for geothermal energy production with supercritical fluids.
This patent grant is currently assigned to The Regents of the University of California. Invention is credited to Donald W. Brown.
United States Patent |
6,668,554 |
Brown |
December 30, 2003 |
Geothermal energy production with supercritical fluids
Abstract
There has been invented a method for producing geothermal energy
using supercritical fluids for creation of the underground
reservoir, production of the geothermal energy, and for heat
transport. Underground reservoirs are created by pumping a
supercritical fluid such as carbon dioxide into a formation to
fracture the rock. Once the reservoir is formed, the same
supercritical fluid is allowed to heat up and expand, then is
pumped out of the reservoir to transfer the heat to a surface power
generating plant or other application.
Inventors: |
Brown; Donald W. (Los Alamos,
NM) |
Assignee: |
The Regents of the University of
California (Los Alamos, NM)
|
Family
ID: |
29736704 |
Appl.
No.: |
09/393,397 |
Filed: |
September 10, 1999 |
Current U.S.
Class: |
60/641.2;
60/641.4 |
Current CPC
Class: |
E21B
41/0064 (20130101); F24T 10/20 (20180501); Y02C
20/40 (20200801); Y02E 10/14 (20130101); Y02C
10/14 (20130101); Y02E 10/10 (20130101) |
Current International
Class: |
F03G
7/00 (20060101); F03G 7/04 (20060101); F03G
007/00 () |
Field of
Search: |
;60/641.2,641.4
;165/45 |
References Cited
[Referenced By]
U.S. Patent Documents
Other References
Brown, D., "The US Hot Dry Rock Program--20 Years of Experience in
Reservoir Testing," Proceedings of the World Geothermal Congress
1995, vol. 4, Florence, Italy, May 18-31, 1995. .
Brown, D. W. "Summary of Recent Flow Testing of the Fenton Hill HDR
Reservoir," Los Alamos National Laboratory publication
LA-UR-94-2856, submitted to Stanford Geothermal Reservoir
Engineering Workshop, (1994). .
Brown, D. W., "How to Achieve a Four-Fold Productivity Increase at
Fenton Hill," Geothermal Resources Council Transactions, vol. 18,
pp. 405-408, (Oct. 1984). .
Brown, D.W., "A Hot Dry Rock Geothermal Energy Concept Utilizing
Supercritical CO2 Instead of Water as the Work Fluids," Abstract,
pp. 1-10, submitted Jan. 3, 1999 to World Geothermal Congress 2000
to be held May 29, 1999 to Jun. 10, 2000 at Kyushu and Tohoku,
Japan. .
Brown, D., DuTeaux, R., "Three Principal Results from Recent Fenton
Hill Flow Testing," Proceedings, Twenty-First Workshop on
Geothermal Resevoir Engineering, Stanford University, Stanford, CA,
pp. 185-190, (Jan. 27-29, 1997. .
Brown, D. DuTeaux, R. Kruger, P., Swenson, D. Yamaguchi, T. "Fluid
Circulation and Heat Extraction from Engineered Geothermal
Reservoirs," Geothermics 00, pp. 1-20, (1999). .
DuTeaux, R., Brown, D., "HDR Reservoir Flow Impedance and
Potentials for Impedance Reduction," Proceeding, Eighteenth
Workshop on Geothermal Reservoir Engineering, Stanford University,
Stanford, CA, pp. 193-197, Jan. 26-28, 1993. .
Saito, S., Sakuma, S. Uchida, T. "Drilling Procedures Techniques
and Test Results For a 3.7 km Deep, 500.degree.C Exploration Well,
Kakkonda, Japan," Geothermics vol. 27, pp. 573-590, (1998). .
Shyu, G., Hanif, N., Hall, K., Eubank, P., "Carbon Dioxide-Water
Phase Equilibria Results from the Wong-Sandler Combining Rules,"
Fluid Phase Equilibria 130, pp. 73-85, (1997). .
Tihanyi, L. and Bobok, E., "A New Way of Heat Recovery: CO2 as a
Geothermal Fluid" Geothermal Resources Council Transactions, vol.
22, pp. 499-502, Sep. 2-23, 1998. .
Vukalovich, M. P., Altunin, V. V., "Thermophysical Properties of
Carbon Dioxide," Collet's (Publishers) LTD., London &
Wellingborough (1968). .
Yost, A. B., Mazza, R. L., Remington, R. E. II, "Analysis of
Production Response to CO .sub.2 /Sand Fracturing: A Case Study,"
SPE 29191, pp. 297-303, Nov. 8-10, 1994. .
Yost, A. B., Mazza, R. L., Gehr, J. B., "CO.sub.2 /Sand Fracturing
in Devonian Shales," SPE 26925, pp. 353-362, Nov. 2-4, 1993. .
Program Announcement to DOE National Laboratories, "Greenhouse Gas
(GHG) Sequestration Applied Research", Federal Energy Technology
Center, Aug. 02, 1999. .
"Final Technical Report, DSA of the Microcracks in More ST-2 Core,
Interpretation and Implications", Nov. 16, 1977..
|
Primary Examiner: Nguyen; Hoang
Attorney, Agent or Firm: Gemma Morrison Bennett
Government Interests
This invention was made with government support under Contract No.
W-7405-ENG-36 awarded by the U.S. Department of Energy. The
government has certain rights in the invention.
Claims
What is claimed is:
1. A method of extracting geothermal energy from an underground hot
dry rock reservoir, comprising the steps of: (a) creating an
underground hot dry rock reservoir by fracturing underground hot
rock with fluid carbon dioxide consisting essentially of carbon
dioxide fluid in the supercritical phase or carbon dioxide fluid
that is transformed into the supercritical phase by the hot dry
rock; (b) allowing the fluid to absorb heat from the hot dry rock
of the reservoir and thereby increase the heat content of the
fluid; (c) removing at least a portion of the fluid having an
increased heat content from the underground hot rock reservoir; and
(d) extracting heat from the portion of fluid having an increased
heat content.
2. The method as recited in claim 1 further comprising the steps
of: (e) reintroducing back into the reservoir at least a portion of
the fluid from which heat has been extracted; (f) allowing the
reintroduced fluid to absorb heat from the hot dry rock again; (g)
removing at least a portion of the reintroduced fluid having an
increased heat content from the underground hot dry rock; and (h)
extracting heat from the reintroduced fluid having an increased
heat content.
3. The method as recited in claim 1 wherein the creation of the hot
dry rock reservoir comprises injecting the fluid into a packed off
interval of an openhole wellbore and thence into a deep region of
hot dry rock.
4. The method as recited in claim 1 wherein the hot dry rock
reservoir is at a depth in the range of from about 1,000 feet to
about 30,000 feet.
5. The method as recited in claim 1 wherein the hot dry rock of the
hot dry rock reservoir has a temperature in the range from about
120.degree. C. to about 1,000.degree. C.
6. The method as recited in claim 5 wherein the temperature of the
hot dry rock of the hot dry rock reservoir has a temperature in the
range of from about 150.degree. C. to about 500.degree. C.
7. The method as recited in claim 1 wherein the hot dry rock of the
hot rock reservoir comprises rock selected from the group
consisting of igneous, metamorphic and sedimentary rock.
8. The method as recited in claim 1 wherein the fluid is injected
at a pressure in the range from about 1,000 psi to about 15,000
psi.
9. The method as recited in claim 1 wherein the fluid is injected
through an open wellbore for an injection period in the range from
about a few hours to several months.
10. The method as recited in claim 1 wherein the fluid is injected
through an open wellbore for an injection period in the range from
about 1 week to about three months.
11. The method as recited in claim 1 wherein the fluid is injected
at a rate in the range from about 20 to 60 kilograms per
second.
12. A method of extracting geothermal energy from an underground
hot dry rock reservoir, comprising the steps of: (a) injecting
fluid consisting essentially of carbon dioxide into an underground
hot dry rock reservoir, the fluid carbon dioxide comprising fluid
in the supercritical phase or carbon dioxide fluid that is
transformed into the supercritical phase by the hot dry rock; (b)
allowing the fluid to absorb heat from the hot dry rock of the hot
dry rock reservoir and thereby increase the heat content of the
fluid; (c) removing at least a portion of the fluid having an
increased heat content from the underground hot dry rock reservoir;
and (d) extracting heat from the portion of fluid having an
increased heat content.
13. The method as recited in claim 12 wherein the fluid is injected
into the underground reservoir region through at least one
injection well.
14. The method as recited in claim 12 wherein the fluid is injected
into the underground reservoir region through a plurality of
injection wells.
15. The method as recited in claim 12 wherein the fluid is
conducted from said reservoir region through at least one
production well.
16. The method as recited in claim 12 wherein the fluid is
conducted from the reservoir region through a plurality of
production wells.
17. The method as recited in claim 12 wherein after the step of
heat extraction the fluid is circulated back into the underground
reservoir.
18. The method as recited in claim 12 wherein the fluid is
conducted from said reservoir region by pumping and thermal
siphoning.
19. The method as recited as recited in claim 12 wherein the hot
dry rock reservoir comprises rocks selected from the group
consisting of igneous, metamorphic and sedimentary rocks.
20. The method as recited in claim 12 wherein the temperature of
the hot dry rock reservoir is in the range from about 120.degree.
C. to about 1,000.degree. C.
21. The method as recited in claim 12 wherein the temperature of
the hot dry rock reservoir is in the range from about 150.degree.
C. to about 500.degree. C.
22. The method as recited in claim 12 wherein the hot dry rock
reservoir is at a depth in the range from about 1,000 feet to about
30,000 feet.
23. The method as recited in claim 12 wherein the fluid is injected
at a pressure in the range from about 1,000 psi to about 15,000
psi.
24. The method as recited in claim 12 further comprising removing
water from the portion of fluid that has been removed from the
reservoir.
25. The method as recited in claim 12 wherein heat is extracted
from the heated fluid using a power generation system in a surface
power plant.
26. The method as recited in claim 25 wherein the heated fluid is
expanded directly into a turbine power generator.
27. The method as recited in claim 25 wherein the heated fluid is
conducted through a heat exchanger, thereby transferring heat to a
turbine power generator working fluid.
28. The method as recited in claim 27 further comprising injecting
the fluid from the turbine power generator back into the
underground reservoir.
29. The method as recited in claim 12 wherein substances that
dissolved into the fluid from the hot rock reservoir are separated
from the fluid after removing the fluid from the hot dry rock
reservoir.
Description
TECHNICAL FIELD
This invention relates to a method and apparatus for geothermal
energy production from hot dry rock reservoirs using supercritical
fluids.
BACKGROUND ART
There have been developed various methods of extracting heat from
dry geothermal (hot dry rock) reservoirs, such as that described in
U.S. Pat. No. 3,786,858 (Potter, et al, Jan. 22, 1974). These
methods rely upon water to hydraulically fracture formations to
form the reservoirs.
Once a fractured reservoir has been formed, production wells are
drilled to intersect the hot dry rock reservoir. Then water, used
as the geofluid, is pumped into the reservoir through the injection
well which was previously used for hydraulic fracturing during
reservoir formation. The water flows across the fractured surfaces
of the hot dry rock, is heated by contact with the hot rock, and
then is used to transfer the geothermal heat to the surface by
flowing upward through one or more production wells in a
pressurized, closed-loop circulating operation referred to as heat
mining.
At the surface, the heat contained in the circulating geofluid is
transferred to a second fluid, referred to as a binary working
fluid, in a high-pressure heat exchanger of conventional design,
and then the cooled geofluid reinjected into the hot dry rock
reservoir. This second fluid, which can also be water, is more
commonly ammonia, or one of a class of halogenated hydrocarbon
refrigerants such as the Freons.TM., or one or a mixture of low
molecular weight hydrocarbons such as isobutane or isopentane.
In common practice, even though the hot pressurized geofluid is
relatively benign chemically, it is not flashed to steam at the
surface because of the release to the environment of small amounts
of environmentally undesirable dissolved materials such as hydrogen
sulfide, boron, arsenic, fluorides and other trace minerals in the
aqueous geofluid. More significant quantities of silica, chlorides,
and carbonates are also typically dissolved in the aqueous
geofluid, potentially causing corrosion and undesirable deposits on
turbine blades and other metallic surfaces in power plants and in
heat exchangers.
Water-based geothermal systems generally have a geochemically
determined temperature limit controlled by the critical point of
water (384.degree. C. and 22 MPa). As the critical point for water
is reached and then surpassed, the enhanced dissolution of silica
followed by retrograde precipitation above 384.degree. C. presents
a substantial obstacle to operating a hot dry rock geothermal
reservoir at higher than the critical temperature for water. For
hot dry rock reservoirs created in the most common igneous and
metamorphic rocks and mixtures of the most common igneous and
metamorphic rocks, where silica is present as either a primary or
secondary (i.e., fracture-filling) mineral, the silica dissolution
and reprecipitation problem occurs as the critical temperature for
water is exceeded. Although drilling systems are capable of
reaching rock temperatures in excess of 400.degree. C., concerns
about enhanced geochemical interactions arise in water-based hot
dry rock geothermal energy systems at these temperatures.
Because of the excellent inorganic solvent properties of water and
because of the slow diffusional flow of water through the
microcrack porosity in underground reservoirs, it is often
difficult to control the chemistry of the water used as the
production geofluid.
Thus, there is still a need for improved methods of producing hot
dry rock geothermal energy.
Therefore, it is an object of this invention to provide another
method for production of geothermal energy.
It is another object of this invention to provide a method of
producing geothermal energy with supercritical fluids.
It is a further object of this invention to provide a method of
producing geothermal energy with supercritical carbon dioxide.
It is still another object of this invention to provide a method of
producing geothermal energy with improved control of the geofluid
chemistry.
It is yet another object of this invention to provide a method of
sequestering carbon dioxide in deep rock formations.
Additional objects, advantages and novel features of the invention
will be set forth in part in the description which follows, and in
part will become apparent to those skilled in the art upon
examination of the following or may be learned by practice of the
invention. The objects and advantages of the invention may be
realized and attained by means of the instrumentalities and
combinations particularly pointed out in the appended claims. The
claims appended hereto are intended to cover all changes and
modifications within the spirit and scope thereof.
DISCLOSURE OF INVENTION
To achieve the foregoing and other objects, and in accordance with
the purposes of the present invention, as embodied and broadly
described herein, there has been invented a method for producing
geothermal energy from deep regions of hot, essentially dry rock
using fluids other than water for creation of underground
reservoirs, production of geothermal energy, and, optionally, as
working fluids in power plants. Underground reservoirs are created
by pumping a supercritical fluid such as carbon dioxide into a rock
mass to fracture the rock. Once the confined geothermal reservoirs
are formed, the same supercritical fluids are circulated into the
geothermal reservoirs, are allowed to heat up and expand, and then
are pumped out of the reservoir to transport the heat to surface
power generating plants or other direct heating applications.
BRIEF DESCRIPTION OF THE DRAWINGS
The accompanying drawings, which are incorporated in and form a
part of the specification, illustrate embodiments of the present
invention and, together with the description, serve to explain the
principles of the invention. In the drawings:
FIG. 1 is a graph of the relationship of amount of injected fluid
to reservoir volume.
FIG. 2 is a graph of solubility of water in carbon dioxide at
250.degree. C. as a function of pressure.
FIG. 3 is a schematic of a set up for production of geothermal
energy in accordance with the invention.
FIG. 4 is a graph of permeability of granitic rock as a function of
pressure.
BEST MODES FOR CARRYING OUT THE INVENTION
It has been discovered that geothermal energy can be produced from
confined dry geothermal (hot dry rock) reservoirs using selected
supercritical fluids. In accordance with the present invention, a
supercritical fluid is used as a fracturing fluid and
heat-transport fluid for deep earth heat-mining systems, and, if
desired, as the working fluid for surface power generating
plants.
The hot dry rock reservoir is created by hydraulically fracturing a
deep region of igneous or metamorphic rock or a deep region of
limestone or other sedimentary rock using a supercritical fluid as
the fracturing fluid. Generally, best results are expected from
fracturing deep regions of essentially impermeable, hot, basement
crystalline rock below sedimentary rock layers. It is contemplated
that the invention will work well in deep crystalline rock
formations such as granite, granodiorite, diorite, mafic igneous
rocks, metamorphic equivalents of any of these, or other
crystalline rocks.
For fracturing the formation to form the hot dry rock reservoir,
one or more injection wellbores are drilled by any suitable method
known in the art. A single injection wellbore is generally
adequate. At least one interval of at least one openhole wellbore
is packed off at the selected depth. Depths are selected to reach a
level where there is sufficient heat in the rock to make
successful, cost effective thermal production practical. Generally,
depths in the range from about 1,000 feet (below surface debris and
sediments and sedimentary rocks) to about 30,000 feet can be used,
depending upon underground thermal conditions.
Underground rock temperatures anywhere from about 120.degree. C.,
below which thermal production would not be cost effective, to
about 1,000.degree. C. or more, with the limitation being the
ability to handle the high temperatures with present well drilling
and completion equipment and materials. Generally, underground rock
temperatures in the range from about 150.degree. C. to about
500.degree. C. are considered more useful in the invention
methods.
Pressurized supercritical fluid is pumped from the surface into the
injection wellbore by any convenient means such as with a postive
displacement or centrifugal pump. The supercritical fluid is
injected into the packed-off interval of an openhole wellbore using
any suitable means such as a high-pressure tubing string.
Injection periods from a few hours to several months may be
required for creating the reservoir region, depending upon the
characteristics of the in situ stress field, the extent and
orientation of fractures and joints already existing in the rock
mass to be fractured, the resistance to flow in the network of
interconnected fractures, the orientation of joint sets in the
region to be fractured, and, most importantly, upon the desired
size of the confined reservoir to be created. Generally an
injection period in the range from about week to about three months
is adequate.
Generally, pumping rates in the range from about 20 to about 60
kg/s are presently preferred, depending upon the actual formation
injection pressure in the packed-off wellbore inerval, because of
pressure and flow capabilities of commercially available pumping
equipment. Surface pumping pressures in the range from about 1,000
psi to about 15,000 psi are generally sufficient to fracture most
formations. When carbon dioxide is used as the supercritical fluid,
then pressures in the range from about 1,100 to about 10,000 psi
are generally useful in the invention method because of the 1073
psi (7.40 MPa) critical pressure for carbon dioxide.
Initially, as the pressure in the packed-off interval is rapidly
increased, one or more of the more favorably oriented natural
joints intersecting the wellbore starts to open under a combination
of tensile (hoop) stresses at the wellbore surface and normal
opening stresses from fluid invasion into the hydrothermally sealed
natural joints (which are somewhat more permeable than the adjacent
unjointed rock). In a region where the natural fractures in the
rock are predominantly vertical, lower pumping pressure is
generally necessary than if the pre-existing fractures or joints in
the rock are predominantly inclined from the vertical. As pumping
continues, the natural fractures or joints progressively open and
interconnect, forming a multiply connected region of
pressure-dilated joints in the rock mass surrounding the packed-off
wellbore interval, thus creating the fractured hot dry rock
reservoir region.
The fracture volume of the reservoir can be as much as ten times or
more greater than the original microcrack pore volume of the
unfractured rock formation. Confined reservoir regions as large as
a cubic kilometer or more can be made by hydraulic fracturing with
supercritical fluids, depending upon how long and at what rate
pressurized supercritical fluid is pumped into the formation during
fracturing of the rock. When carbon dioxide, with a density about
equal to that of water, is used as the supercritical fluid, about a
cubic meter of supercritical fluid will open up about 4,000 cubic
meters of reservoir, as shown in FIG. 1. FIG. 1 is a graph showing
the linear relationship between reservoir volume and volume of
injected fluid as determined from microseismic event location data
in a test of a region stimulated by injecting fluid under high
pressure.
Supercritical fluids which can be used in the practice of the
invention include, but are not limited to, carbon dioxide,
halogenated hydrocarbon refrigerants such as Freons.TM., arnmonia,
mixtures of ammonia and water, low molecular weight hydrocarbons
such as propanes, butanes and hexanes, and mixtures thereof.
Supercritical carbon dioxide, halogenated hydrocarbon refrigerants,
hydrocarbons and mixtures thereof are more preferred than ammonia
and mixtures of ammonia and water because of the corrosive
properties of supercritical ammonia and the possibility of
vigorous, exothermic reactions of supercritical ammonia and water
mixtures.
Carbon dioxide is generally presently most preferred as the
supercritical fluid because it is readily available, easily
handled, economical, generally chemically inert, and accepted by
the public as nonhazardous. Using carbon dioxide as the geofluid
has the additional advantage of providing a way to sequester carbon
dioxide from flue gases or other industrial process effluents by
using and maintaining the carbon dioxide deep in the earth and
allowing a portion of it to slowly diffuse into the surrounding
rock mass.
Additives can be incorporated into the supercritical fluid before
introduction into the injection borehole or can be added to the
circulating fluid anywhere convenient in the flow path of a
closed-loop system. Additives can be employed for inhibition of
corrosion of casing, piping, pumping equipment, and power
generation plant equipment such as heat exchangers. Additive
amounts of other fluids can be used to adjust the physical and
thermodynamic properties of the fluid, such as the density, or the
critical pressure and temperature of the supercritical fluid.
Additive amounts of water can be used in supercritical ammonia for
the same purposes.
During hydraulic fracturing using supercritical carbon dioxide,
almost all of the original naturally occurring pore fluid
(generally a brine) present in the microcrack porosity of the
fractured reservoir is dissolved in the amount of supercritical
fluid used to create the reservoir. For a typical hot dry rock
reservoir at a depth of 4 km and for a rock temperature of
260.degree. C., and assuming a reasonable surface injection
pressure of 30 MPa (fluid conditions of 67 MPa and 250.degree. C.
within the reservoir), at least a 24 mol percent solubility of
water in the supercritical carbon dioxide can be anticipated. FIG.
2 shows the solubility of water in supercritical carbon dioxide at
250.degree. C. as a function of the pressure of the solution.
When carbon dioxide is used as the supercritical fluid, the mineral
constituents originally dissolved in the initial pore fluid within
the reservoir are left behind as mineral precipitates when the pore
fluids in turn dissolved by the supercritical carbon dioxide, since
these minerals such as silica and chlorides are generally not
soluble in the supercritical carbon dioxide.
If the hot dry rock reservoir is being created in sedimentary rock
or other formations which contain methane and other hydrocarbons,
and if carbon dioxide or another fluid which dissolves hydrocarbons
is used as the supercritical fluid, then it may be necessary to
incorporate a separation step when the supercritical fluid is first
circulated back up to the surface. Separation of the hydrocarbons
from the supercritical fluid can be accomplished using any
conventional method such as separation with propylene carbonate
membranes or by chilling the mixture to distill out the
hydrocarbons.
At the periphery of the hot dry rock fractured reservoir region of
the rock mass, the supercritical fluid slowly diffuses outward to
the much-lower-pressure far field from the pressurized reservoir.
If carbon dioxide is used as the supercritical fluid, the
pre-existing water-filled network of interconnected microcracks in
the surrounding rock mass is slowly flushed with the supercritical
fluid, and the pore fluid is dissolved, leaving behind mineral
precipitates which tend to partially plug the microcrack porosity
and slowly seal the reservoir boundaries.
After the desired volume of rock is fractured (i.e., pressure
stimulated), the pressure of supercritical fluid being injected is
reduced to a pressure at which the system is stabilized with no
further fracture extension, i.e., no more rock is being fractured
at the periphery of the reservoir and, therefore, the reservoir is
no longer being enlarged. In this manner a large region of
fractured rock bounded by surrounding almost-impermeable
unfractured rock is created--the confined hot dry rock
reservoir.
For production of thermal energy from the hot dry rock reservoir,
one or more production wellbores are drilled into the fractured
zone using any suitable drilling method. Since the deep earth
stress field is normally anisotropic, the pressure-stimulated
reservoir region will tend to be elongated in some direction, but
still symmetrical about the injection well that was used to create
the fractured region that is the reservoir. Therefore, in almost
all cases it will be preferred to access the reservoir with a
plurality of production wells. For example, in ellipsoidal-shaped
hot dry rock reservoirs, production wells could be drilled at each
end furtherest from the injection well. Generally presently
preferred are two production wells drilled to penetrate the
reservoir near either end of the elongated region. This three-well
(one injection, two production) strategy usually is most cost
effective. An example of this is shown in the schematic of FIG.
3.
In the schematic of FIG. 3 fluid is pumped by injection pump 12
into a single injection well 14 into a reservoir region 16.
Pressure and supercritical fluid from the reservoir region 16
circulates up one of two production wells 18 and 20 to the surface
22 where the supercritical fluid is circulated through conduits 24
and 26 back to the injection pump 12 which pumps the fluid back
down the injection well 14. A portion of the conduits carrying the
heated supercritical fluid from downhole passes through a heat
exchanger 28 where heat is transferred to conduits 30 carrying a
power plant 32 working fluid.
In a typical production process in accordance with the invention,
following the drilling of one or more production wells, pressurized
supercritical fluid is re-injected into the reservoir through at
least one injection well. The same wellbore used to fracture the
rock to form the reservoir is generally used as the injection
wellbore. Initially, sufficient supercritical fluid to
re-pressurize the reservoir, to establish circulation, and to make
up for supercritical fluid diffusing into the rock mass surrounding
the reservoir region, is introduced into the injection well.
After formation of the reservoir, an initial period of water
separation from the supercritical fluid may be used as needed,
especially in closed loop systems, to eliminate from the system
water brought up from the reservoir region dissolved in the
supercritical fluid or in another phase. Once the amount of water
coming out of the reservoir is reduced to a very small amount, the
need for corrosion inhibition measures during geofluid circulation
is virtually obviated.
When desired, because total reservoir flow is dependent primarily
on the near-production-wellbore flow impedance, additional lateral
production wells can be used. Generally, two additional lateral
production wells, one off of each of two initial near-vertical
production wells, would be used. This arrangement could
approximately double the production flow rate, and therefore the
thermal power output, for the total cost of one additional well
since each lateral leg costs about 50% of the cost of an initial
wellbore.
When carbon dioxide is used as the supercritical fluid in the
practice of this invention, the carbon dioxide remains in the
supercritical phase in the reservoir because of the elevated
pressure. If other fluids such as ammonia, low molecular weight
hydrocarbons or halogenated hydrocarbon refrigerants are used as
the geofluid, the fluid is pumped into the injection well as a
compressed liquid and may then change from the liquid to the
supercritical phase when subjected to the elevated downhole
temperatures.
The supercritical fluid is heated by transfer of energy from the
hot rock surfaces it comes into contact with in the reservoir. As
the supercritical fluid is heated it expands to some extent, losing
density.
The very significant difference in the density of the cold injected
supercritical circulating fluid in the injection wellbore (which
can be as much as about 1.0 g/cc for carbon dioxide) and the
density of the hot produced circulating fluid in the production
wellbore or wellbores (which can be as little as about 0.3 g/cc for
carbon dioxide) provides an impressive bouyant drive or thermal
siphoning of the geofluid which greatly reduces the required
circulating pumping power compared to that required for geofluid
circulation in a comparable water-based hot dry rock geothermal
energy system.
An amount of supercritical fluid sufficient to achieve an
appropriate level of reservoir pressurization and then sufficient
to establish and maintain reservoir circulation by the thermal
siphoning of the supercritical fluid circulating through a
closed-loop system is pumped down at least one injection well into
the reservoir region. Depending upon what demands are made on the
fluid circulation system at the surface, the thermal siphoning may
be adequate to keep the fluid circulating indefinitely without much
pumping assistance at all. For example, if the supercritical fluid
is circulated by itself in a closed loop back down the injection
well as would be done in a binary power generating system, the
supercritical fluid could be circulated with minimal or no need for
additional pumping. With the exception of very minor losses of
pressure through surface heat exchangers used to transfer
geothermal heat to binary cycle working fluids, the pressure of the
hot supercritical fluid thermally siphoned out of the reservoir
would be equal to the injection pressure for the cold supercritical
fluid. Conversely, if the supercritical fluid is pumped directly
into an expansion turbine without use of heat exchange equipment,
then pumping assistance would be required for reinjection at the
surface.
Additional supercritical fluid is used for fluid makeup at the
surface to compensate for the small amount of supercritical fluid
slowly diffusing into the rock mass surrounding the pressurized hot
dry rock reservoir region.
Fluid makeup with pure supercritical fluid combined with an initial
period of water removal, eventually reduces the amount of dissolved
water in the circulating supercritical fluid to a very small
amount. This eliminates the need for any water separation equipment
in the surface power plant following one initial pre-production
reservior diagnostic phase lasting a few months.
Any supercritical carbon dioxide escaping the system is relatively
harmless since it is essentially nonhazardous in dilute
concentrations.
Surface conduits of a kind and configuration known in the art are
used to convey the heated supercritical fluid from the well head to
any of a variety of applications which require thermal energy.
Presently contemplated, in addition to surface electric power
generating plants, are applications such as space heating,
preheating materials for chemical processes, drying pumice and
minerals mined in a way that produces wet products, heating
greenhouses, drying crops, heating water, and for any other
direct-heat application requiring a moderate-temperature hot
fluid.
There are at least two different approaches that can be used when
the heated supercritical fluid is used for power generation:
conventional binary-cycle turbine power generation and direct drive
of a turbine with the heated supercritical fluid.
In a first approach, a binary heat transfer system method could be
used to achieve superior thermodynamic efficiency (approximately a
factor of 3 higher heat utilization rate than in a direct-expansion
turbine method), particularly when carbon dioxide is the
circulating supercritical fluid. In this alternative, isobutane, a
halogenated hydrocarbon refrigerant, liquid ammonia or another
suitable binary-cycle working fluid is circulated through a heat
exchange system where it is heated by the hot supercritical
geofluid circulated up from the reservoir. Then, in turn, the
heated binary-cycle working fluid is used to provide heat energy to
the turbine. The binary-cycle working fluid is pumped under
pressure into a heat exchanger or boiler in contact with the heated
supercritical geofluid where the binary-cycle working fluid is
vaporized. The expanding vapor spins the turbine while losing
pressure and temperature, and is then circulated through a cooling
tower where it is condensed to the liquid phase. The liquid phase
binary-cycle working fluid is pumped back into the heat exchanger
where it is once again heated and vaporized by the circulating
geofluid.
In a second approach, the hot circulating geofluid from the
production wellbore or wellbores can be expanded directly into a
power generating turbine, since there are essentially no dissolved
solids in the circulating geofluid. In the power generating
turbine, the supercritical fluid (carbon dioxide is presently
preferred) expands isentropically to a lower temperature and
pressure. Then, after a significant amount of heat rejection
(cooling) at constant pressure, the dense, cooled but still
supercritical fluid is reinjected into the confined hot dry rock
reservoir. Pumping is generally required for circulation of the
geofluid through a closed loop system using this approach.
In this direct introduction of the geofluid into the turbine, the
inability of supercritical fluids to dissolve and transport mineral
constituents from the geothermal reservoir to the surface would
eliminate mineral scaling effects in the surface piping and power
plant equipment. Using halogenated hydrocarbon refrigerants or
hydrocarbons as the supercritical fluid would prevent corrosion of
equipment which could occur if small amounts of water were
dissolved in supercritical carbon dioxide, forming carbonic acid
which would react with metals.
This second approach eliminates the need for primary heat
exchangers or surface fluid cleanup or gas separation systems as
used in conventional binary-cycle geothermal power plants. Cooling
towers or air-cooled heat exchangers are used as needed for heat
rejection from the turbine outflow, where the supercritical fluid
is expanded directly in the power-generating turbine.
Although it is not necessary in either of the two approaches to
power generation using hot dry rock geothermal energy, to recycle
the cooled supercritical fluid from the power generation plant back
down the injection well or wells in a closed-loop system, that is
the presently preferred mode of operation because it conserves the
geofluid (and its pressure in the binary-cycle mode) and prevents
environmental effects that could result from releasing the geofluid
into the-atmosphere. This would be particularly so if the fluid
were a flammable hydrocarbon, a halogenated hydrocarbon
refrigerant, or ammonia.
Problems associated with traditional geothermal reservoir operation
temperatures being limited by the critical point for the water
(384.degree. C. and 22 MPa) used as a circulation fluid are not
encountered with use of supercritical carbon dioxide as the
production fluid because the supercritical carbon dioxide is not a
solvent for the inorganic materials found in igneous and
metamorphic rocks. Thusly, the potential problems associated with
dissolved minerals and other materials are avoided. This allows for
supercritical-fluid-based hot dry rock production temperatures
approaching 400.degree. C. or even higher, with the ultimate
temperature generally being determined by the temperature limits of
the drilling system.
When the relatively small amount of pore fluid originally in place
in the deep basement rock is dissolved in the supercritical carbon
dioxide, its dissolved mineral constituents are left behind as a
small amount of mineral precipitate within the microcrack pore
structure. Therefore, problems in water-based geothermal energy
production systems associated with other trace materials in
solution such as arsenic, fluoride and boron are avoided by use of
supercritical carbon dioxide as the production fluid.
Indeed, when the dissolved mineral constituents are left behind as
precipitates, the precipitates tend to slowly plug off the
microcrack porosity at the periphery of the hot dry rock fractured
region, slowly sealing the reservoir boundaries even more
completely than the usually almost impermeable range of several
hundredths of a microdarcy. Therefore, the slow outward diffusion
of supercritical carbon dioxide from the periphery of the hot dry
rock fractured region to the far field from the pressurized
reservoir is further slowed.
Engineered hot dry rock reservoirs are inherently confined
reservoirs. The chemistry and nature of the circulating fluid can
be specified by the operator because there is a minimum of fluid
leakoff from the hot dry rock reservoir region after an initial
start-up period. Thus, only a small percent of the circulating
fluid is lost to fluid leakoff from the periphery of the hot dry
rock reservoir.
The engineered reservoirs of this invention have other important
advantages over naturally occurring reservoirs. The developer can
specify the reservoir operating conditions. The geofluid injection
pressure and temperature, and the geofluid production pressure can
be tailored to accomplish the production goals while accommodating
naturally occurring conditions. The size of the hot dry rock
reservoir is determined by the operator through the selection of
the rate and duration of fluid injection during reservoir creation
by hydraulic fracturing. The expected production temperature is
selected by choice of reservoir depth (and therefore rock
temperature).
In accessing the fractured reservoir region, the operator has a
choice as to the optimum production strategy, based upon both
production engineering and financial considerations. Conventional
means of productivity enhancement can be used with the
supercritical critical carbon dioxide geothermal production methods
of this invention. For example, multilateral production wells can
be drilled and used. Several methods of production well flow
impedance reduction can be employed. These include methods such as
repeated pressure and temperature cycling of the near-production
wellbore network of flowing fractures or use of chemical means to
selectively dissolve certain of the constituent minerals occurring
along the fracture surfaces.
Because the invention hot dry rock reservoirs are engineered rather
than naturally occurring, other operating options are available.
For example, if the reservoir were to be operated at an injection
pressure just above the fracture extension pressure, then the
reservoir region could be continually grown in a very controlled
manner while providing an additional increment in power production
because of the increased level of injection pressure and,
therefore, a reduction in the overall reservoir flow impedance. In
addition, the amount of carbon dioxide sequestration would increase
accordingly. If carefully controlled, this slow reservoir growth
could effectively double the size of the hot dry rock reservoir in
a decade. At that time a slow drop in the production temperature
would be anticipated if the production strategy had been well
planned. In a reservoir that had been grown in this manner over a
decade, the production well or wells could then be converted into
injection wells and more production wells drilled further away from
the original injection well site. This would essentially double the
lifetime of the hot dry rock heat mine at the cost of drilling only
the additional production well or wells while other capital costs
had already been substantially amortized.
When supercritical carbon dioxide is used as the geofluid in a hot
dry rock geothermal energy system, the invention can make a
significant contribution to solving a developing worldwide
environmental problem--that of continued global warming due to
ever-increasing atmospheric concentrations of carbon dioxide, one
of the so-called "greenhouse gases." This contribution by the
invention is provided in three ways: (1) by tying up in the
geofluid inventory of the closed-loop hot dry rock circulation
system a large amount of carbon dioxide that would otherwise end up
in the atmosphere; (2) by replacing an equivalent amount of
fossil-fueled energy production with clean, nonpolluting hot dry
rock geothermal energy; and (3) by sequestering, over time, a very
significant amount of carbon dioxide deep in the earth through the
diffusion of supercritical carbon dioxide into the rock mass
surrounding the fractured hot dry rock reservoir.
To elaborate upon the third point, A hot dry rock geothermal power
plant in accordance with the present invention has the capability
of continuously sequestering, by diffusion into the surrounding
rock mass, about as much carbon dioxide as that produced by a
typical coal-fired power plant, considering each on a per
MW-electric basis: 24 tons of carbon dioxide per day per MW(e).
Also, with regard to the third point, for certain types of igneous
and metamorphic rocks comprising the rock mass, the hot
supercritical carbon dioxide diffusing outward from the hot dry
rock reservoir region is chemically bound up in the rock by
carbonating the contained calcic feldspars (e.g., labradorite or
anorthite). That is, for supercritical carbon dioxide diffusing
through hot, microcracked felsic or silicic rocks (e.g., granite,
granodiorite, diorite or gabbro), the carbon dioxide reacts with
the contained calcic feldspars, producing calcium carbonate as a
precipitate with clays and other geochemically altered materials.
Thus, the outward diffusion of carbon dioxide provides for
long-term sequestration, with the carbon dioxide being chemically
bound up in the rock mass. This eliminates any environmental
consequences from the possible slow leakoff of carbon dioxide from
the near-reservoir region to the environment.
The following examples will demonstrate the operability of the
invention.
EXAMPLE I
In a constructive reduction to practice using data from an
analogous geothermal production system, a confined hot dry rock
reservoir is created by fracturing a region of hot, dry igneous
Precambrian crystalline rock located at Fenton Hill in the Jemez
Mountains of north central New Mexico. Core samples of igneous and
metamorphic rock obtained from depths ranging from 1.2 to 2.8 km
show that the mean in-situ rock mass porosity is about 0.009% under
in-situ stress conditions, and that the corresponding permeability
is of the order of 0.1 to 0.01 microdarcies.
FIG. 4 is a graph of measured permeabilities for three granitic
core samples from Fenton Hill relative to the effective
pressure.
Following the drilling and completion of a full-diameter deep
injection well to a depth of about 4 km, the well is prepared for
the subsequent fracturing operation by pressure-isolating the
bottom 500 m or so of the uncased wellbore. This is done by
installing and cementing in a scab liner about 500 meters off
bottom, with a high pressure frac string connecting the liner to
the surface. The wellbore and frac string are then purged of all
drilling fluid and other water-based fluids by unloading the hole
with gaseous carbon dioxide supplied from one or more of a variety
of conventional sources, with the carbon dioxide pumped to the
bottom of the hole through coiled tubing.
Then, supercritical carbon dioxide is injected from the surface
through the frac string and into the pressure-isolated interval of
openhole wellbore, using high pressure commercial fracturing pumps.
The region being fractured is a pre-jointed body of Precambrian
biotite granodiorite centered at a mean depth of 4 km with a
temperature of about 260.degree. C.
The rate of injection is maintained at about 50 to 100 pounds per
second for a period of several weeks or more, until a suitably
large fractured hot dry rock reservoir is created. The desired
volume of the fractured reservoir is up to 1/2 cubic kilometer or
more, which requires the injection of about 125,000 cubic meters of
supercritical fluid, according to the data shown in FIG. 3. At an
injection rate of 100 lb/s, this volume requires a pumping time of
about 30 days. The actual injection rate is controlled by
maintaining the surface injection pressure at less than 5000 psi,
the most economical injection pressure range when using commercial
pumping equipment for an extended period of time.
During the entire period of reservoir creation, the growth of the
reservoir is monitored microseismically to determine its developing
shape and orientation, to allow the determination of the optimum
placement for the two (or more) production wells to be subsequently
drilled. This is done by recording, with an array of near-surface
geophones, the hydraulic-fracturing-induced seismicity generated by
shear slippage along the network of pressure-dilating joints within
the reservoir region. The array of geophones is emplaced in shallow
wells surrounding the injection well.
Two or more production wells are then drilled to optimally access
the man-made confined hot dry rock geothermal reservoir. During the
latter stages of the drilling of one or more of these production
wells, and during a pause in drilling operations, the reservoir is
grown an increment larger, again using supercritical carbon
dioxide, to allow timely "mid-course" corrections to the drilling
trajectories of the production wells.
To determine the need for mid-course corrections, a temporary
geophone would be installed at the bottom of the selected
production well during the pause in drilling to monitor the
microseismicity occurring during the period of renewed reservoir
growth resulting from additional hydraulic fracturing. This is to
provide a more accurate assessment of the shape and orientation of
the hot dry rock reservoir than was initially obtained using only
the surface seismic array.
Finally, the hot dry rock circulating system is completed by
drilling the two or more production wells to intersect the
reservoir near each end of the elongated reservoir region as
defined by the "cloud" of microseismic event locations defining the
shape of the fractured hot dry rock reservoir. All the wells would
be appropriately completed with casing to the surface and then
purged of drilling fluids and other water-based materials, again
using gaseous carbon dioxide.
EXAMPLE II
In a constructive reduction to practice, a half-year pre-production
test of the confined hot dry rock reservoir constructively created
in Example I is made.
Following the reservoir creation and flow loop development phases
of Example I, the hot dry rock reservoir is flow-tested for a
period of about half a year to establish and verify all the
necessary operating parameters for the design of an appropriate
surface power plant or other heat utilization system.
The parameters that need to be measured and verified are: (a) the
geofluid production temperature; (b) the production flow rate and
the reservoir pressure drop and reservoir flow impedance, all as
functions of injection and production pressure levels; (c) the
distribution of the flow impedance across the reservoir; (d) the
amount of water dissolved in the produced supercritical carbon
dioxide as a function of time--and the success in methods of water
removal; and (e) the temporal variation in the rate of diffusion of
the geofluid outward from the fractured hot dry rock reservoir into
the rock mass surrounding the reservoir (i.e., the geofluid loss
rate as a function of time).
The temporal variation in the rate of diffusion of the geofluid
outward from the fractured hot dry rock reservoir is the principal
measurement in establishing the rate of carbon dioxide
sequestration in the rock mass surrounding the hot dry rock
reservoir.
Based on the wealth of Fenton Hill hot dry rock reservoir
performance data already available and allowing for a factor of
three increase in the diffusively of supercritical carbon dioxide
compared to water under comparable reservoir conditions of
temperature and pressure (250.degree. C. and 52 MPa), it is
anticipated that the geofluid loss rate from the periphery of a 1/2
cubic kilometer reservoir region, at the end of 6 months of
reservoir flow testing, would be about 7 pounds per second.
This closed-loop flow testing would be done by the simple expedient
of wasting the produced geothermal heat to the atmosphere in an
air-cooled heat exchanger. A high-pressure injection pump would be
used to establish the initial level of reservoir pressurization and
to maintain that level of pressurization during the establishment
of circulation, but might not be needed once steady-state flow
conditions with buoyant circulation are established.
During the period of flow testing under a variety of surface
operating pressures, active seismic monitoring of the
near-reservoir region would be maintained to determine the degree
of confinement of the fractured hot dry rock reservoir and whether
any reservoir leakage paths have developed. This data, in
combination with the temporal variation in the rate of geofluid
loss from the reservoir, are the two principal quantities needed in
determining the degree of confinement of the hot dry rock
reservoir.
At the end of this period of preliminary reservoir flow testing,
all the data and parameters needed for designing and fabricating an
optimum surface power plant are in hand and the reservoir is fully
verified with respect to power production potential and
longevity.
While the apparatuses, articles of manufacture, methods and
compositions of this invention have been described in detail for
the purpose of illustration, the inventive apparatuses, articles of
manufacture, methods and compositions are not to be construed as
limited thereby. This patent is intended to cover all changes and
modifications within the spirit and scope thereof.
INDUSTRIAL APPLICABILITY
The invention method and apparatus can be used for production of
geothermal energy from hot dry rock reservoirs using supercritical
fluids. Practice of the invention also provides a means for
sequestration of carbon dioxide that is produced in combustion
processes or otherwise obtained such that the carbon dioxide is not
released to the atmosphere to contribute to continuing global
warming.
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